South Australia transmission company ElectraNet says it has found a cheaper solution that using the state’s gas plants to provide system strength to the local grid, which is now dominated by wind and solar.

ElectraNet says it proposes to install three “synchronous condensers” in key areas of the state – at a cost of around $80 million – to ensure that gas-fired generators will no longer need to be switched on just to ensure the grid remains stable.

The proposal is yet another sign of the rapid change in South Australia’s grid, which is now beyond 50 per cent of wind and solar in local generation, and is also leading the way in the adoption of battery storage.

This has meant that the Australian Energy Market Operator has had to call on older and more expensive generators to satisfy its new equations for guaranteeing “system strength”.

This in turn has resulted in higher prices over the last month, and has coincided with a near doubling in AEMO directions to the market – to an extraordinary 73 per cent of trading intervals in the last four weeks.

The equations for system strength, which now number more than 20 different combinations of gas and diesel generators, were introduced last July as part of the AEMO response to the previous blackouts and load-shedding.

Some in the market think AEMO is being highly conservative on system strength – which seeks to stabilize voltage levels (inertia is generally required to maintain frequency).

As ElectraNet and AEMO have pointed out, South Australia has the highest penetration of wind, compared to the size of its grid, than anywhere else in the world, and wind can provide more than 120 per cent of demand at certain times.

But according to ElectraNet, those directions or interventions may not be necessary in the future if its proposed use of synchronous condensers is approved.

At the instigation of AEMO, EectraNet conducted a tender of gas generators for the provision of system strength, but the offers were too expensive.

ElectraNet found that by placing three condensers at strategic parts of the grid, then

This is significant.

The Tesla big battery near the Hornsdale wind farm has already changed the way operators and owners are thinking about the management of the grid, now that they have at hand technology which is faster and more accurate than conventional plant, and is slashing prices.

Now, ElectaNet has found that using synchronous generators is cheaper than contracting with existing generators which currently also provide inertia and system strength essentially for free.

“It suggests that the cost of providing these services is quite manageable, and cheaper compared to the current practice of issuing directions to gas generators in South Australia,” says Dylan McConnell, from the Climate and Energy College in Melbourne.

The use of synchronous condensers and its ability to reduce the need to rely on conventional generation is an important consideration as South Australia heads towards a market share of 75 per cent wind and solar by 2025.

Even though the new Liberal state government does not share the previous Labor government’s target of 75 per cent renewables by 2025, the target is likely to be met before that anyway, given the current construction and the intentions of Whyalla steel owner Sanjeev Gupta to power that facility with up to 1GW of solar and storage.

Its tender and subsequent analysis concluded that contracts with gas generators would not be economic based on generator costs, and installing synchronous condensers on the network is the least cost solution.

“No other realistic options are available to meet the need in the required timeframe.

Installing network synchronous condensers is a no regrets measure to meet an immediate need. Any future sources of system strength available will help address wider constraints on the power system.

ElectraNet says installing synchronous condensers will avoid the need for costly generator direction by AEMO, and this is expected to result in a net cost saving equivalent to $3 to $5 per year on a typical South Australian residential electricity bill.

“Directing generators is an interim operational solution only, and is unlikely to remain a viable option,” it notes.

An ElectraNet spokesperson said in an emailed statement that the final costs will be known once detailed specification and design work is finalised in coming months, but around $80 million had been allowed.

“The savings are the expected net impact of the cost to implement the solution and it is expected that this solution will largely eliminate the need for special system strength directions by AEMO. “

A synchronous condenser operates in a similar way to large electric motors and generators.

It contains a synchronous motor whose shaft is not directly connected to anything, but spins freely and is able to adjust technical conditions on the power system.

Electranet says the synchronous condensers are expected to be operational within 18-24 months.

It says detailed technical analysis is being undertaken in consultation with AEMO and manufacturers to determine the number, size, specification and design of the synchronous condensers required to meet the system strength gap.

Giles Parkinson is founder and editor of Renew Economy, and is also the founder of One Step Off The Grid and founder/editor of The Driven. Giles has been a journalist for 35 years and is a former business and deputy editor of the Australian Financial Review.

Giles Parkinson is founder and editor of Renew Economy, and is also the founder of One Step Off The Grid and founder/editor of The Driven. Giles has been a journalist for 35 years and is a former business and deputy editor of the Australian Financial Review.

49 Comments

Peter F 10 months ago

It is probably true that synchronous condensors are cheaper than running gas turbines, but it is not necessarily true that they are cheaper than synthetic inertia from windfarms and batteries. The advantage for Electranet is that they capture the returns from the synchronous condensors whereas the windfarm owners capture the revenue from synthetic inertia. Having said that diversity is usually a good thing and synchronous condensors are a very well understood technology so having a few on the system can’t hurt too much

LN 10 months ago

System security is largely about voltage support and fault clearance, whilst inertia relates to system frequency. It is my understanding that windfarms, being inverter connected, don’t provide the kind of fault current/voltage support that synchronous solutions do, and that batteries are not currently capable of providing these services (unless I am mistaken?).

Frank Speaking 10 months ago

Yes. Inverters are electronic devices and can sync to the Atomic clock if needed or whatever signal/freq it is needed to sync to

Chris Drongers 10 months ago

Interesting question – would the electricity grid still work if all inverters were set to synchronise on a microsecond atomic clock signal. As I understand the current system ‘slops’ around a desired frequency but is not particularly concerned about maintaining synchronicity with an external marker.

I could be wrong but I understood our grid was similar. Any time outside of frequency had to be made up for to keep the clocks correct. 6 minutes is a bit beyond the pale though.

Ian Porter 10 months ago

This is called virtual oscillator control and is used in Hawaii for example. It is a very good way of maintaining system reference frequency as the ratio of synchronous to non-synchronous generation reduces.

neroden 10 months ago

The problem is fundamentally that inverters are digitally chopping the waveform; if you want to get a true sine wave, which some equipment cares about, you need something synchronous to smooth it out. One synchronous condenser per metro area should be sufficient.

Mike Westerman 10 months ago

Hopefully once several of the pumped hydro schemes are commissioned around 2022-23, they will supply synch con, real power support and reserve and time shifting of solar and wind, all at much lower costs than gas!

Tim Forcey 10 months ago

TYPO?

Something missing right before “This is significant”?

Might be significant!

GlennM 10 months ago

Great article I learnt something new. Hope this proceeds anything to allow more RE and less Carbon is a good thing.

Rod 10 months ago

I thought AGL had a plan to convert one or two of the Torrens Island A station units into synchronous condensers when they decommission the boilers. Also, given it is likely to be a Fossil unit tripping that will need the system security provided by these, surely they must bear some of the costs.

LN 10 months ago

Actually Rod, the system security issue is generally a transmission line fault

Rod 10 months ago

Granted the system black was due to 3 of 4 transmission lines failing between the primary source and the primary load but I fail to see a similar scenario happening sans hurricane.

I am in the camp that finds these restrictions very conservative and expected them to be relaxed after the election.

LN 10 months ago

I think perhaps you are confusing system security (voltage support and fault clearance) with frequency/inertia? The system black was due to protection settings on some wind farms reacting to low voltages resultant from transmission faults. The reduction in output from wind farms was picked up by the Heywood interconnector, which tripped on loss of synchronism protection. This was a large loss of supply and the frequency drop was unrecoverable.

Transmission faults are not uncommon – lightening strikes, animals and trees can all be causes. If there is insufficient system strength this can result in a cascading voltage collapse and disconnection of (all forms of) generators. I think it prudent to protect against another system black or large impact system event, don’t you?

Rod 10 months ago

Surely voltage support comes from inertia? Hypothetically, if Pt Augusta was still running and providing SA the same amount the wind was that night (and TIPS was doing SFA) and the same transmission fault happened, what would the outcome be? Why is it the costs for voltage support are being lumped on RE assets and not FF units? Why have the governor settings on the FF units been allowed to be relaxed.

LN 10 months ago

Voltage support comes from reactive power, which is required in a very short time frame.

By Pt Augusta you mean Northern Power Station? My feeling is it would have ridden through the faults and there would have been no issue. The issue was the protection settings on certain wind farms (which have since been adjusted). Not sure if it has been implemented, but a protection scheme for the interconnector was being investigated to shed load to avoid having the interconnector trip to protect itself (which would leave SA islanded and the potential for frequency to drop unrecoverably as in the system black event).

The costs for the current directions for system strength are levied on consumers (and not RE – as a side note, most types of FF generator provide voltage support). The need for voltage support arises from transmission faults, and all kinds of generators and loads require this voltage support (as they are designed to operate within certain voltage thresholds) to remain connected to the grid. As to your point on governor settings, it looks like re-enabling them will be imposed on generators.

Rod 10 months ago

Can’t agree on Northern. 500MW supplying Adelaide and the lines down with no-where for those electrons to go would have meant instant trips on both units. = Lights out. As for the wind farms. The self protection was set to two rather than the max (10 maybe) faults. Even AEMO weren’t willing to guess the outcome if the settings were at max. With lines on the ground, after 10 resets = lights out. The only way to avoid this was to: a)Suspend the market b)Get TIPS supplying more to Adelaide (constrain wind) c)Limit the interconnector flows. This event was well forecast. I recall on the news, vision of all the emergency services being briefed the night before. By all means, next time we have similar storms forecast, enact the onerous spinning gas requirement. But the current restrictions are all about protecting the system should a big FF unit fail,

LN 10 months ago

There are 4x 275kV lines between Davenport (Northern) and Adelaide. 2 of them were damaged by high winds/tornadoes (which wasn’t forecast) within 15 seconds of each other. A third was blown over (time unknown), whilst the forth remained in service (and there’s some linkage through the 132kV also), so Northern wouldn’t have been disconnected from the rest of SA. AEMO would have reclassified the loss of Northern with only 1 line remaining – they would have constrained Northern output (so as to not being overly reliant on it) and potentially the interconnector, so there would have been a price signal for generators to come online, or AEMO might have directed generators. As an aside, if Pt Augusta had been disconnected from the rest of SA, there is also load in that area that would have been disconnected (ie Tony’s favourite Whyalla and Olympic Dam).

The drops in voltage following transmission faults triggered wind farm protection schemes. Northern would have some reactive power output, hence voltage would not have dropped as much at its connection point, and it would not have entered fault ride-through like the wind farms did.

The system strength requirement is at all times, it is just that the directions come at times of high wind or low demand when gas not economic. They are providing a service, but are not going to do so at a loss. Again, this is about transmission faults, not generator trips.

I’m not saying that Northern is all great and powerful and that coal is good, just that different generation types have different characteristics, and there are services that synchronous generators provide that non-synchronous do not. If we want a high penetration of non-synchronous renewables and the retirement of FF we still need to ensure that the grid is run securely.

David Osmond 10 months ago

thanks for the info LN. Do you know what the thermal rating was of the remaining line? Would it have been able to take all the power from the 3 downed lines?

LN 10 months ago

The remaining Davenport-Bungama line is rated to ~430MW – as to whether it could take the power from the 3 downed lines it depends what was flowing over them at the time, the timing of the lines tripping, the loads/generation along their path, and whether there are protection schemes in place, so I can’t really say. If the load at Davenport and to the north/west of there was 430MW the line could probably take some short-term overload prior to tripping – potentially for the 2 minute period until the next dispatch interval.

The third line tripped after the system black. If it was more than 2 minutes after the other lines, this would have been into the next dispatch interval, and AEMO likely would have imposed some constraints to reflect the line outages. Perhaps the control room might have taken additional steps, who knows?

David Osmond 10 months ago

Thanks LN. Correct me if I’m wrong, but if the wind farms didn’t trip, then most of the 455 MW that they were generating, plus some more from other wind farms north of the transmission faults minus the load in the NW would have had to flow down that one remaining line. Could have been close to the thermal limit…

Pg 33 of the above report shows a map, pg 112 a SLD of the 275kV network – you’ll see that a number of the windfarms ie Mt Lock, Hornsdale, The Bluff, Nth Brown Hill, Hallett and Hallett Hill are on the Adelaide side of the Davenport-Belalie/Mt Lock lines which failed. Brinkworth-Templers West had already failed, and at some later point on the same flow path Davenport-Brinkworth was damaged. However along that western path there was still another 275kV line from Davenport to Adelaide via Bungama, and some meshing with the 132kV, so probably would have been ok?

Chris Baker 10 months ago

Another thing to consider is AEMO’s view of what is a credible contingency event. If Northern was operating AEMO would have assumed one of its units could trip and would have allowed for this in their planning. This may have meant more headroom on the interconnector. It seems they did not consider such a large loss of wind generation was a credible event, and so didn’t allow for it. In the case of the 2005 event two units tripped together and this was not considered a credible event by NEMMCO. Both cases are very similar in that the events were not considered credible by the market operator, and not enough contingency reserve was allowed.

LN 10 months ago

They already reserve headroom on the interconnector for FCAS/contingency – if you look at one of the reports at http://nemweb.com.au/reports/current/Dispatch_Reports/ you’ll see that whilst the export limit of Heywood is 600MW the FCASEXPORT limit is 950MW (roughly in line with the design capacity). When Heywood was down I have seen circumstances when the output of a Torrens B unit was restricted to the amount of raise service available in SA because loss of that unit was the largest credible contingency (well Pelican was online but has a min load of 170MW and they needed it online so I guess they would just have to deal with it by shedding load, see below).

There is a balance between the cost of procuring reserve in the form of contingency FCAS, and the likelihood of an event occurring. Contingency FCAS is procured for credible contingencies, whilst for non-credible contingencies it is acceptable to (in the worst case) manage by shedding load – it should not, however, result in a system black.

AEMO did not consider such a loss of wind as a credible contingency at the time, although you’ll see in the system black report that they recategorised the loss of a group of wind farms as a credible contingency until they understood the cause and became convinced it was no longer credible due to updating the protection settings.

Chris Baker 10 months ago

Hi LN, that interesting information. I had wrongly assumed the interconnector had disconnected due to overload current, rather than a combination of high current and low voltage, that caused the protection to operate.

I suppose this is suggesting that such a scheme would act faster than the HPR would detect a frequency event and increase its discharge rate anyway?

LN 10 months ago

This scheme does act faster as it will be triggered by the (more or less) instantaneous loading on the interconnector – contingency (and regulation) FCAS which you are referring to is co-ordinated by AEMO and is “dispatched” only every 4 seconds. Contingency is only dispatched when frequency is outside of the deadband at the point of this snapshot (in this case <49.85Hz) – whilst you might lose supply in SA, it remains connected to the rest of the NEM and the large amount of inertia so frequency won't decline too much. The issue arises once Heywood is overloaded and trips to protect itself – SA is left islanded from the rest of the NEM, having just lost a large supply in the form of Heywood, the frequency plunges and a LOT of load has to be shed to keep the system stable.

No surprise that the monopoly network company prefers the solution that allows them to build assets and stick them in its regulated asset base…

BushAxe 10 months ago

AEMO forecasted a NSCAS gap years ago when Northern’s closure was announced along with increased RE generation. Electranet looked at repurposing Northern’s generators into condensers but it never happened for some reason. AEMO has been waiting for a AEMC rule change that went through last year that makes networks responsible for system strength. This now means AEMO can declare a NSCAS gap and issue a direction to the network to fill the gap without needing a RiT-T to prove its viability, speeding up the development process. Although it will go into Electranet’s RAB customers will benefit in the longer term from reduced generation costs. Next phase will be to link the batteries to enable better system balancing of load/generation after faults (the SIPS project).

AndrewATA 10 months ago

Yeah Northern should have been repurposed into a synchronous condenser. But it didn’t happen because ownership/control of the power system is fragmented and there’s no proper planning/coordination. Alinta as the owner of Northen had no responsibility for such things, so they just closed it quickly without regard for syn cons etc.

Now it’s a scramble to catch up with events. We need much better planning, especially as the transition to renewables continues.

zadaki 10 months ago

I thought SA electric power cost was equal to the most expensive in world? It’s ok for a sheltered workshop economy, or a small model to test ideas, but before you scale you must get the economies of scaling up right. China is often touted by the Greens as an exemplar of investment into alternative energy but temper that with in reality they also have over 2,500 coal powered power stations. That is ~ 200 times more of those polluting types than Australia.

Catprog 10 months ago

However most of them run for less time then the wind turbines.

Peter F 10 months ago

Not really. thermal CF is around 46% (terrible) but wind is only around 28% (not very good)

Mike Westerman 10 months ago

The real point is less the capacity factor per se but how much it differs from that used for the business case. For many wind farms 28% would be adequate but for a baseload thermal station 46% would be a disaster.

CF is the equivalent full load hours. In China coal is running at 46% and wind 27%. It is true that wind is gradually rising with better technology but that is partially offset by installations in the Southeast which have lower average wind speeds. It is extremely unlikely that China will get much over 30-32% wind CF in the next 5 years. In a sense because of more hostile policy in Australia wind farm site and turbine selection has been more discriminating so on average our wind farms perform much better

If we are lucky China coal utilisation might fall to 38% or alternatively coal plant closures will climb rapidly so while coal output is gradually replaced individual plants maintain or increase utilisation. If closures result in higher CF for remaining coal plants it is still a surprisingly good thing on three levels, a) presumably most of the closed plants will be less efficient ones b) running plants at high capacity factors reduces their emissions per MWh c) less competition means higher prices which improves competitiveness of low marginal cost renewables

Ray Miller 10 months ago

The solution of using synchronous condensers smacks of an outdated engineering solution with no long term focus. I’m not questioning the need for the service or placement but with the newer battery storage technologies providing the equivalent service plus many more and likely to be better overall “value” for money and usefulness. While our engineers may be comfortable (warm and cozy feeling ) with having more spinning machines at some point the 21st century beckons. The cost of further introducing another different type of equipment adds significant hidden (training, maintenance, spare parts etc) and ongoing costs which are likely to dominate the initial capital cost many fold and be uneconomic quickly into the future.

But then again it may be cheaper the retire the current engineers and employ those who are capable identifying what the real problem is first before they dive into short term expensive solutions which will be a white elephant from day one?

I’d like to be proven wrong but with many examples of lazy outdated engineering in our NEM history it is proving to be difficult and expensive to progress the industry.

neroden 10 months ago

Synchronous condensers have a record of lasting upwards of 80 years, and you really only need one per metropolitan region to “clean up” the waveform. Once you’ve got one, it eliminates all of the “problems” associated with putting lots and lots of batteries on the grid.

Greg Hudson 9 months ago

And what happens when one fails / goes offline for some reason ?

mick 9 months ago

who cares deploy them in pairs for redundancy in my view its more about the big picture

Matthew Cole 10 months ago

Just watch the LNP ruin all the good work South Australians have been doing for yrs.

Ian 10 months ago

How much do these synchronous condensers cost and are there alternatives?

Ian 10 months ago

Like other grid options, there are local distributed, solutions and large scale grid solutions. Static VAR compensators are generally behind the meter, and these big synchronous condensers are centralised grid options. VAR costs a company a lot and conditioning inductance load behind the meter makes financial sense.

The more the grid becomes an electric highway system, with many points of entry and exit, the more distributed solutions will matter. There is a real danger of white-elephantism, but hey these guys have probably done their homework.

phred01 10 months ago

more stranded assets

neroden 10 months ago

Synchronous condensers are basically spinning magnets. They’re quite cheap and they smooth out the waveform artifacts in AC which are caused by digital inverters. It makes sense to have one in each grid region, and they don’t cost much.